U.S. patent application number 14/431011 was filed with the patent office on 2015-08-27 for method and device for downhole corrosion and erosion monitoring.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Robert S. Atkinson, Li Gao, Michael T. Pelletier, David L. Perkins.
Application Number | 20150240627 14/431011 |
Document ID | / |
Family ID | 52628814 |
Filed Date | 2015-08-27 |
United States Patent
Application |
20150240627 |
Kind Code |
A1 |
Gao; Li ; et al. |
August 27, 2015 |
Method and Device for Downhole Corrosion and Erosion Monitoring
Abstract
Methods and systems for monitoring material loss in a downhole
environment arising from corrosion and/or erosion include placing a
downhole sensor in a borehole. The resistance of the downhole
sensor is measured using a four-probe resistance technique in which
a power source is provided at two electrodes of the downhole sensor
and voltage is measured at two voltage taps. A rise in voltage over
time indicates loss of conductive material on the downhole sensor.
The conductive material on the downhole sensor may be formed to
provide discrete voltage increases for improving reliability of
material loss and/or rate of material loss resistance
measurements.
Inventors: |
Gao; Li; (Katy, TX) ;
Pelletier; Michael T.; (Houston, TX) ; Atkinson;
Robert S.; (Richmond, TX) ; Perkins; David L.;
(The Woodlands, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
52628814 |
Appl. No.: |
14/431011 |
Filed: |
September 6, 2013 |
PCT Filed: |
September 6, 2013 |
PCT NO: |
PCT/US2013/058444 |
371 Date: |
March 25, 2015 |
Current U.S.
Class: |
422/82.02 ;
324/700 |
Current CPC
Class: |
G01V 3/26 20130101; E21B
41/02 20130101; G01N 17/04 20130101; E21B 47/13 20200501 |
International
Class: |
E21B 47/12 20060101
E21B047/12; G01N 17/04 20060101 G01N017/04; G01V 3/26 20060101
G01V003/26 |
Claims
1. A downhole sensor for downhole monitoring of material loss,
comprising: a conductive portion formed as a unitary solid
structure and comprising at least two electrodes and at least two
electrical pathways, wherein electrical current flows across the
electrical pathways when supplied from a power source connected to
the electrodes, and wherein each electrical pathway in the
conductive portion is formed with a cross-sectional area that is
unique with respect to the other electrical pathways in the
conductive portion; and an insulating substrate upon which the
conductive portion is placed, wherein a material composition of at
least one electrical pathway is selected based on a material loss
process of a downhole component.
2. The downhole sensor of claim 1, wherein a chemical composition
of the conductive portion is selected to match a chemical
composition of the downhole component.
3. The downhole sensor of claim 1, wherein the conductive portion
mimics the material loss process of the downhole component, and the
material loss process includes a process selected from at least one
of: a corrosion process and an erosion process.
4. The downhole sensor of claim 3, wherein the material loss
process includes a corrosion process and the material composition
of the at least two electrical pathways is selected based at least
on a reactivity with a chemical species found in a downhole
fluid.
5. The downhole sensor of claim 3, wherein the material loss
process includes an erosion process and the material composition of
the at least two electrical pathways is selected based at least on
a hardness of a particulate found in a downhole fluid.
6. The downhole sensor of claim 3, wherein, an increase in a
voltage occurs when the material loss process severs a first
cross-sectional area for a first electrical pathway, and wherein
the increase in the voltage corresponds to at least a detection
limit for downhole monitoring of the voltage.
7. The downhole sensor of claim 6, wherein the detection limit is
at least three times greater than a peak-to-peak noise level of the
voltage.
8. The downhole sensor of claim 6, wherein the increase in the
voltage is a characteristic value for a failure of the downhole
component, and further comprising: the power source.
9. The downhole sensor of claim 1, wherein the insulating substrate
and the conductive portion are formed with a curved geometry to
conform to a tubular structure of at least a portion of a downhole
component, and wherein the downhole component is selected from at
least one of: a borehole casing and a drillstring.
10. The downhole sensor of claim 1, wherein the insulating
substrate is mechanically flexible.
11. A method for downhole monitoring, comprising: providing a
downhole sensor located in a borehole, the downhole sensor
comprising an insulating substrate and a conductive portion on the
insulating substrate, the conductive portion including at least two
electrodes; electrically activating the downhole sensor by
supplying an electrical current from a power source connected to
the at least two electrodes to create a voltage across the
conductive portion; monitoring the voltage to determine a change in
resistivity of the conductive portion; and determining an amount of
material loss of a downhole component located in the borehole based
on the change in resistivity of the conductive portion, wherein the
downhole sensor mimics a material loss process of the downhole
component.
12. The method of claim 11, wherein the material loss process is
selected from at least one of: erosion and corrosion.
13. The method of claim 11, wherein the insulating substrate and
the conductive portion are formed with a curved geometry to conform
to a tubular structure of at least a portion of the downhole
component, and wherein the downhole component is selected from at
least one of: a borehole casing and a drillstring.
14. The method of claim 11, wherein the insulating substrate is
mechanically flexible.
15. The method of claim 11, wherein the conductive portion is a
unitary solid structure comprising a plurality of electrical
pathways across which the electrical current flows, and wherein
each of the plurality of electrical pathways is associated with a
cross-sectional area that is unique with respect to the other
electrical pathways in the conductive portion.
16. The method of claim 15, wherein the cross-sectional area is
formed by altering, for an electrical pathway, at least one of: a
width and a height, and wherein a material composition of the
electrical pathway is selected based on a reactivity with a
chemical species found in a fluid in the borehole.
17. The method of claim 15, wherein, when the material loss process
severs a first cross-sectional area for a first electrical pathway
included in the plurality of electrical pathways, an increase in
the voltage occurs, and wherein the increase in the voltage
corresponds to at least a detection limit for downhole monitoring
of the voltage.
18. The method of claim 17, wherein the detection limit is at least
three times greater than a peak-to-peak noise level of the
voltage.
19. The method of claim 15, further comprising: determining a rate
of the material loss process based on recorded times at which the
increase in the voltage occurs when the first electrical pathway
and a second electrical pathway in the conductive portion are
respectively severed.
20. A system for downhole monitoring of material loss, comprising:
a downhole sensor comprising a conductive portion formed as a
unitary solid structure, the solid structure including at least two
electrodes for connection to a power source, and at least two
electrical pathways each formed with a respectively unique
cross-sectional area compared to other electrical pathways in the
conductive portion, wherein electrical current flows across the
electrical pathways when supplied from the power source; a material
loss monitor comprising a processor having access to memory media,
the power source, and an analog to digital converter to measure
voltage, wherein the material loss monitor collects voltage data
from the downhole sensor; and an insulating substrate upon which
the conductive portion is placed.
21. The system of claim 20, wherein the material loss monitor is in
continuous communication with the downhole sensor, and wherein the
power source is continuously supplied with electrical power.
22. The system of claim 21, wherein the continuous communication is
wireline communication.
23. The system of claim 21, wherein the continuous communication is
wireless communication.
24. The system of claim 20, wherein the material loss monitor is in
intermittent communication with the downhole sensor, and wherein
the power source is intermittently supplied with electrical
power.
25. The system of claim 24, wherein the intermittent communication
and the power source are provided using radio-frequency coupling
from a logging tool inserted into the borehole.
26. The system of claim 21, wherein the material loss monitor is
located in the borehole.
Description
BACKGROUND
[0001] This disclosure relates generally to subterranean drilling
operations and, more particularly, to monitoring corrosion and
erosion in a downhole environment.
[0002] Hydrocarbons, such as oil and gas, are commonly obtained
from subterranean formations that may be located onshore or
offshore. The development of subterranean operations and the
processes involved in removing hydrocarbons from a subterranean
formation are complex. Typically, subterranean operations involve a
number of different steps such as, for example, drilling a borehole
at a desired well site, treating the borehole to optimize
production of hydrocarbons, and performing the necessary steps to
produce and process the hydrocarbons from the subterranean
formation.
[0003] During drilling and production operations, various pieces of
equipment are exposed to the downhole environment where corrosion
and erosion, particularly of metal parts, may occur. Due to the
presence of corrosive chemicals, such as, but not limited to,
H.sub.2S and CO.sub.2, and abrasive particulates, metallic
equipment in the downhole environment of well installations is
subject to corrosion and erosion. Such corrosion and erosion may
represent a serious risk of equipment failure. Particularly when
downhole equipment fails unexpectedly, for example, due to unknown
degrees of corrosion and erosion, a number of associated economic
disadvantages for a drilling operator may result, such as
undesirable downtime of drilling operations and unplanned repairs
and replacement of affected downhole equipment.
FIGURES
[0004] Some specific exemplary embodiments of the disclosure may be
understood by referring, in part, to the following description and
the accompanying drawings.
[0005] FIG. 1 is a block diagram of selected elements of an
embodiment of an example drilling system;
[0006] FIG. 2A is a block diagram of selected elements of an
embodiment of a downhole sensor;
[0007] FIG. 2B is a block diagram of selected elements of an
embodiment of a downhole sensor;
[0008] FIG. 2C is a block diagram of selected elements of an
embodiment of a downhole sensor;
[0009] FIG. 2D is a block diagram of selected elements of an
embodiment of a downhole sensor;
[0010] FIG. 3A is a block diagram of selected elements of an
embodiment of a downhole sensor;
[0011] FIG. 3B is a block diagram of selected elements of an
embodiment of a downhole sensor;
[0012] FIG. 4 is a block diagram of selected elements of an
embodiment of a material loss monitor;
[0013] FIG. 5 is a block diagram of selected elements of an
embodiment of a material loss monitor;
[0014] FIG. 6 depicts a flow chart of selected elements of an
embodiment of a method for performing material loss resistance
measurements; and
[0015] FIG. 7 is a block diagram of selected elements of an
embodiment of a computer system.
[0016] While embodiments of this disclosure have been depicted and
described and are defined by reference to exemplary embodiments of
the disclosure, such references do not imply a limitation on the
disclosure, and no such limitation is to be inferred. The subject
matter disclosed is capable of considerable modification,
alteration, and equivalents in form and function, as will occur to
those skilled in the pertinent art and having the benefit of this
disclosure. The depicted and described embodiments of this
disclosure are examples only, and are not exhaustive of the scope
of the disclosure.
DESCRIPTION OF PARTICULAR EMBODIMENT(S)
[0017] The present disclosure relates generally to well drilling
operations and, more particularly, to monitoring corrosion and
erosion in a downhole environment.
[0018] Illustrative embodiments of the present disclosure are
described in detail herein. In the interest of clarity, not all
features of an actual implementation may be described in this
specification. It will of course be appreciated that in the
development of any such actual embodiment, numerous implementation
specific decisions must be made to achieve the specific
implementation goals, which will vary from one implementation to
another. Moreover, it will be appreciated that such a development
effort might be complex and time consuming, but would nevertheless
be a routine undertaking for those of ordinary skill in the art
having the benefit of the present disclosure.
[0019] To facilitate a better understanding of the present
disclosure, the following examples of certain embodiments are
given. In no way should the following examples be read to limit, or
define, the scope of the disclosure. Embodiments of the present
disclosure may be applicable to horizontal, vertical, deviated,
multilateral, u-tube connection, intersection, bypass (drill around
a mid-depth stuck fish and back into the well below), or otherwise
nonlinear boreholes in any type of subterranean formation.
Embodiments may be applicable to injection wells as well as
production wells, including natural resource production wells such
as hydrogen sulfide, hydrocarbons or geothermal wells. Devices and
methods in accordance with embodiments described herein may be used
in one or more of wireline, slickline, measurement while drilling
(MWD) and logging while drilling (LWD) operations. Embodiments
described below with respect to one implementation, such as
wireline, are not intended to be limiting. Embodiments may be
implemented in various formation tools suitable for measuring, data
acquisition and/or recording data along sections of the formation
that, for example, may be conveyed through flow passage in tubular
string or using a wireline, slickline, tractor, piston,
piston-tractor, coiled tubing, downhole robot or the like.
[0020] FIG. 1 shows an existing drilling system 100. The drilling
system 100 includes a rig 102 mounted at the surface 122,
positioned above a borehole 104 within a subterranean formation
106. The rig 102 may be connected to multiple drilling pipes 118
and 120 via a top drive 126. The drilling system 100 may include a
pipe-in-pipe drilling system where an inner pipe 120 is disposed
within an outer pipe 118. Drilling muds, for example, may be pumped
into the borehole 104 within the annulus defined by inner pipe 120
within outer pipe 118. The drilling mud may be pumped downhole
through bottom hole assembly (BHA) 108 to drill bit 110. The BHA
108 may include a corrosion/erosion monitoring tool 114 and/or
other LWD/MWD element 112, which may be coupled to outer pipe 118
and inner pipe 120. In certain embodiments, the drilling fluid may
return to the surface 122 within annulus 116, or be diverted into
inner pipe 120. A control unit 124 at the surface 122 may control
the operation of at least some of the drilling equipment.
[0021] In FIG. 1, drilling system 100 may further include material
loss monitor 130, which may be coupled to downhole sensor 132 via a
wireline (not shown) in an exemplary communication embodiment. In
other embodiments (not shown), downhole sensor 132 may communicate
with material loss monitor 130 via various means, that may depend
upon a placement of downhole sensor 132. In some embodiments, at
least a portion of downhole sensor 132 and/or related equipment may
be located within the pipe-in-pipe drilling system. Although
material loss monitor 130 is depicted in drilling system 100 as
being located at surface 122, material loss monitor 130 may be
positioned as desired for a particular operation, including, at
least in part, within borehole 104. Material loss monitor 130 may
include a computer system (see FIG. 7) and associated
instrumentation (see also FIGS. 4 and 5) for performing downhole
material loss monitoring for corrosion and/or erosion processes, as
described herein.
[0022] In operation, as drilling mud circulates past various
downhole components of drilling system 100, corrosion and/or
erosion of the downhole components may occur during normal
operation. The corrosion and/or erosion may adversely affect
performance and service lifetimes of the downhole components.
Corrosion refers to undesirable chemical reactions that may consume
a material from which a pipe-in-pipe drilling system, and/or other
equipment (not shown) is formed. Erosion refers to mechanical
abrasion, for example, from exposure to abrasive particles in a
pressurized drilling fluid, which may cause material to be eroded
and physically removed over time. Thus, corrosion and erosion may
represent separate material loss processes that undesirably consume
material from which downhole equipment is formed. Even though a
corrosion process and an erosion process may occur concurrently,
each process may be selective for a material composition of the
affected equipment. For example, a rate of the corrosion process
may depend upon a specific composition of steel used for forming
downhole components of the pipe-in-pipe drilling system. Also, a
rate of the erosion process may depend upon a hardness (or
toughness) of a downhole material, which may also depend upon
composition. The erosion process may further depend upon a hardness
of particulate matter found in the drilling fluid that acts as an
abrasive and may accordingly depend upon a geological composition
of subterranean formation 106. Also, although downhole sensor 132
is shown mounted on outer pipe 118, it is note that in other
embodiments, downhole sensor may be mounted in different
arrangements, for example, on a surface of corrosion/erosion
monitoring tool 114.
[0023] As will be described in further detail herein,
corrosion/erosion monitoring tool 114 may be equipped for
monitoring corrosion and/or erosion using downhole sensor 132 in a
manner that mimics corrosion and/or erosion of at least one
downhole component, in order to ascertain a rate of corrosion
and/or erosion of the downhole components. Corrosion/erosion
monitoring tool 114 may also determine whether the
corrosion/erosion processes have damaged a given downhole component
to an unacceptable level by removing so much material as to warrant
replacement of the downhole component. Furthermore, material loss
monitor 130, in conjunction with downhole sensor 132, may enable
monitoring of material loss in the downhole environment from
corrosion and/or erosion in a manner that is relatively insensitive
to noise and that may be chemically specific for particular
material compositions and/or reactants.
[0024] Referring now to FIG. 2A, a block diagram of selected
elements of an embodiment of downhole sensor 200 is illustrated. As
shown in the sectional depiction of FIG. 2A, downhole sensor 200
may include conductive portion 210 and insulating substrate 212. In
various embodiments, conductive portion 210 may be a thick or thin
conductive layer, such as a metal film. Conductive portion 210 may
be deposited, or grown, on insulating substrate 212 using a variety
of techniques, such as sputtering, thermal evaporation, laser
ablation, atomic layer deposition, chemical vapor deposition, etc.
In some embodiments, conductive portion 210 may be a metal sheet or
foil that is joined with insulating substrate 212 using an adhesive
(not shown). In particular embodiments, a chemical composition of
conductive portion 210 may be selected to match a chemical
composition of a downhole component in the borehole, which
conductive portion 210 is designed to mimic in terms of material
loss due to corrosion and/or erosion. A material composition of
insulating substrate 212 may be selected for electrical insulation,
chemical inertness in the downhole environment, as well as
toughness/hardness in order to be resistant to material loss from
corrosion and/or erosion. In one example, insulating substrate 212
includes an alumna ceramic.
[0025] Referring now to FIG. 2B, a block diagram of selected
elements of an embodiment of downhole sensor 201 is illustrated. As
shown in the sectional depiction of FIG. 2B, downhole sensor 201
may include conductive portion 210 and insulating substrate 212, as
described previously with respect to FIG. 2A. As shown, downhole
sensor 201 has been formed with a curved geometry to conform to a
tubular structure, such as a borehole casing and/or a drill string,
among other examples of downhole equipment and components.
Furthermore, in some embodiments, insulating substrate 212 may be
formed to be mechanically flexible, for example, to be able to
conform to an arbitrary geometry (not shown) in the downhole
environment. The mechanical flexibility may arise, at least in
part, from a geometry and/or dimension of a particular instance of
insulating substrate 212. The mechanical flexibility may also
arise, at least in part, from a material composition of insulating
substrate 212.
[0026] Referring now to FIG. 2C, a block diagram of selected
elements of an embodiment of downhole sensor 202 is illustrated. As
shown in FIG. 2C, downhole sensor 202 may include conductive
portion 210 and insulating substrate 212, as described previously
with respect to FIG. 2A. In FIG. 2C, downhole sensor 202 is shown
in a top view, yet may have a similar sectional portrait as
downhole sensor 200 (see FIG. 2A) or downhole sensor 201 (see FIG.
2B). As shown in FIG. 2C, conductive portion 210 is formed in a
distinct pattern to facilitate resistance measurements in a
four-probe configuration, in which two electrodes, represented by
current taps 214, are used to inject electrical current from a
current source (see FIG. 4) and two voltage taps 216 are used to
measure a resulting voltage difference. The resistance R at any
given time of downhole sensor 202 is given by Equation 1 below.
R = V I = .rho. t L W = R s * g Equation ( 1 ) ##EQU00001##
In Equation 1, V is the voltage measured across voltage taps 216, I
is the current across current taps 214, .rho. is the resistivity of
a material used to form conductive portion 210, g is a geometric
factor equal to length L divided by width W of conductive portion
210, t is a thickness of conductive portion 210, and R.sub.s is a
sheet resistance given by .rho./t. Thus, based on Equation 1, the
thickness t of conductive portion 210 may be determined at any time
from a resistance measurement. When the resistance measurements are
repeated over time, the change in t over time may be determined and
may be correlated with a rate of material loss due to corrosion
and/or erosion in the downhole environment.
[0027] Referring now to FIG. 2D, a block diagram of selected
elements of an embodiment of downhole sensor 203 is illustrated. As
shown in FIG. 2D, downhole sensor 203 may include conductive
portion 210 and insulating substrate 212 (not shown in FIG. 2D), as
described previously with respect to FIG. 2A, although only
conductive portion 210 is shown in FIG. 2D for descriptive clarity.
In FIG. 2D, downhole sensor 203 is shown in a top view, yet may
have a similar sectional portrait as downhole sensor 200 (see FIG.
2A) or downhole sensor 201 (see FIG. 2B). As shown in FIG. 2D,
conductive portion 210 is formed in a distinct pattern to
facilitate resistance measurements in a four-probe configuration,
in which two current taps 214 are used to inject electrical current
from a current source (see FIG. 4) and two voltage taps 216 are
used to measure a resulting voltage difference. The design of
downhole sensor 203 may be based on a Van der Pauw configuration,
in which a symmetric structure is used to measure sheet resistance
using a difference between voltages V1 and V2, as given by Equation
2.
R = V 1 - V 2 I Equation ( 2 ) ##EQU00002##
Then, the sheet resistance R.sub.s and thickness t for downhole
sensor 203 may be given by Equations 3 and 4.
R s = .rho. t = .pi. ln ( 2 ) R Equation ( 3 ) t = ln ( 2 ) .rho.
.pi. R Equation ( 4 ) ##EQU00003##
[0028] Turning now to FIG. 3A, a block diagram of selected elements
of an embodiment of downhole sensor 300 is illustrated. As shown in
FIG. 3A, downhole sensor 300 may include conductive portion 210 and
insulating substrate 212, as described previously with respect to
FIG. 2A. In FIG. 3A, downhole sensor 300 is shown in a top view,
yet may have a similar sectional portrait as downhole sensor 200
(see FIG. 2A) or downhole sensor 201 (see FIG. 2B).
[0029] In FIG. 3A, downhole sensor 300 has been formed based on a
Fallon ladder, in which electrical pathways 310 represent rungs on
a ladder structure. Electrical pathways 310 in downhole sensor 300
may have individually varying widths and/or lengths, and
accordingly, varying resistances. In particular embodiments, each
electrical pathway 310 is associated with a unique cross-sectional
area and, therefore, a unique contribution to an overall resistance
of downhole sensor 300. As compared with downhole sensors 200, 201,
202, 203 (see FIGS. 2A-D), downhole sensor 300 may provide certain
advantages for material loss determination. Specifically, due to an
expected level of noise associated with small voltage signals
arising from a low resistance of a metal structure, a differential
increment of the voltage signal in a four-probe resistance
configuration may be difficult to ascertain. Particularly when
material loss rates are desired at relatively short time intervals,
downhole sensor 300 may provide certain unique advantages by
flowing current through electrical pathways 310. For example, when
a particular one of electrical pathway 310 is ultimately severed
due to material loss from corrosion and/or erosion, an overall
change (i.e., reduction) in resistance of downhole sensor 300 may
be a discrete value that results in a corresponding discrete change
(i.e., increase) in the measured voltage. Since the discrete change
in the measured voltage due to severing of electrical pathway 310
is generally greater than a change in voltage from a gradual loss
of material in the downhole environment, downhole sensor 300 may
provide indications of material loss with a higher degree of
certainty than other types of conductivity probes.
[0030] In FIG. 3A, the dimensions and arrangement of electrical
pathways 310 in downhole sensor 300 may be selected based on
various factors. For example, a difference in cross-sectional area
between any two adjacent electrical pathways 310 may be dimensioned
such that a resulting voltage increase upon severing is
statistically significant with respect to noise on the voltage
signal. In certain embodiments, the resulting voltage change from
severance of electrical pathway 310 may be at least a magnitude of
a detection limit for a baseline voltage noise level, such as a
noise level in the downhole environment. The detection limit may
correspond to three (3) times a peak-peak value of the baseline
voltage noise level. It is further noted that, as a result of
improved sensitivity for certain measurement points due to the
arrangement of electrical pathways 310, downhole sensor 300 may
accordingly provide improved rate of material loss measurements
with a higher degree of certainty than other arrangements of
conductive portion 210. A rate of the material loss process may be
determined, for example, by recording times at which at least two
electrical pathways 310 are severed. In certain embodiments,
downhole sensor 300 may be formed specifically to provide a desired
number of distinct voltage signals resulting from severing of
electrical pathways 310 in order to determine the rate of material
loss. In given embodiments, an electrical pathway 310 included in
downhole sensor 300 may be dimensioned to provide a characteristic
value related to a particular downhole component, for example, by
mimicking a failure to due material loss of the downhole component.
In this manner, downhole sensor 300 may be used to provide a
reliable pass/fail test at an arbitrary and/or desired time for a
given downhole component. Although downhole sensor 300 provides
greater sensitivity in certain aspects, as described above,
downhole sensor 300 may still be used in a four-probe resistance
configuration with a single current source and a single voltage
measurement, which is advantageous in terms of cost and
complexity.
[0031] Advancing now to FIG. 3B, a block diagram of selected
elements of an embodiment of downhole sensor 301 is illustrated. As
shown in FIG. 3B, downhole sensor 301 may include conductive
portion 210 and insulating substrate 212, as described previously
with respect to FIG. 3A. In FIG. 3B, downhole sensor 301 is shown
as a sectional view of an embodiment of downhole sensor 300, in
which a thickness of each of electrical pathways 310 has been
varied to vary the cross-sectional area.
[0032] As shown in FIGS. 3A and 3B, it will be understood that a
combination of variation of width and/or thickness of electrical
pathways 310 may be practiced in other embodiments. It is further
noted that a material composition of at least one electrical
pathway 310 may be varied (not shown) to achieve a desired chemical
specificity with regard to corrosion reactions in the downhole
environment. In this manner, downhole sensor 301 and/or 300 may be
used to detect or identify the presence of a particular chemical
species from a measured change in resistivity. For example, in the
presence of aqueous hydrogen sulfide (H.sub.2S), it is known that
iron (Fe) may be oxidized to iron sulfide (FeS), which may be
distinctly detected by resistance measurements using downhole
sensor 301 and/or 300. Other dimensional and/or compositional
variations for selective detection of material loss in the downhole
environment may be practiced in different embodiments.
[0033] Referring now to FIG. 4, a block diagram of selected
elements of an embodiment of material loss monitor 400 is
illustrated. As shown, material loss monitor 400 may represent
functionality for performing material loss resistance measurements,
as described herein. In some embodiments, at least certain portions
of shown in FIG. 4 may be implemented in material loss monitor 130
and/or downhole sensor 132 (see FIG. 2).
[0034] In FIG. 4, power source 410 may represent a source of
electrical power used to power various elements. For example, power
source 410 may provide electrical power to current source 402 for
applying current 412 to material loss sensor 404 to perform
resistance measurements. Power source 410 may also provide power
for data acquisition 406, which measures voltage 414 across
material loss sensor 404 as a result of current 412 being applied.
Power source 410 may also provide power to transmitter 408, which
may transmit measurement results to a computer system for further
processing. Current source 402 may be a source of electrical
current and may be coupled to material loss sensor 404 via two
current taps (see FIGS. 3A, 3B). In certain embodiments, current
source 402 may include a voltage source and a load resister (not
shown) over which current is provided. Material loss sensor 404 may
represent at least a portion of downhole sensors 200, 201, 202,
203, 300, 301 (see FIGS. 2A-2D, 3A, 3B). Data acquisition 406 may
include a digitizer, such as an analog-digital converter, for
acquiring and digitizing voltage values and/or calculating a
thickness from measured voltage values. Transmitter 408 may be a
wireline and/or wireless transmitter, in different embodiments.
[0035] In certain embodiments where line power is available, power
source 410 may represent line power, while transmitter 408 may
represent a wired communication channel that can provide galvanic
and/or optical connectivity up the borehole. When line power is not
available, power source 410 may represent a battery, while
transmitter 408 may represent a wireless communication channel,
such as an acoustic channel, mud pulse telemetry, electromagnetic
telemetry, etc. It is noted that material loss monitor 400 may
operate in a continuous and/or intermittent manner for performing
material loss resistance measurements, as described herein.
[0036] Referring now to FIG. 5, a block diagram of selected
elements of an embodiment of material loss monitor 500 is
illustrated. As shown, material loss monitor 500 may represent
functionality for performing material loss resistance measurements,
as described herein. As shown, material loss monitor 500 may
represent an embodiment of passively powered material loss
resistance measurements, such as in a permanent downhole
installation where power and/or communication channels are not
available.
[0037] In FIG. 5, material loss monitor 500 is shown comprising
radio frequency (RF) transmitter 522 and RF receiver 520. RF
transmitter 522 includes transmit/store data 516, demodulation 514,
RF power (reader) 512, and antenna 518. RF receiver includes power
supply 502, load modulation 504, processor 508, memory media 510,
and sensor interface 511, which may include at least certain
portions of material loss monitor 400 (see FIG. 4). RF receiver 520
may be permanently installed downhole, while RF transmitter 522 may
be mounted on a logging tool that passes by RF receiver 520.
[0038] In operation, RF power (reader) 512 may radiate RF power
from antenna 518 to antenna 519, which receives the RF power. Under
control of processor 508 having access to memory media 510, at
power supply 502, the RF power is rectified and a charge pump is
used to provide DC power for other elements included in RF receiver
520, as well as for providing power for generating current at
sensor interface 511. Sensor interface 511, which may include a
downhole sensor and data acquisition, as described herein, may
provide digitized voltage data. Processor 508 may then send current
and voltage data via antenna 519 to antenna 518 using load
modulation 504 to digitally switch a load impedance on and off, for
example. The change in impedance is detected by demodulation 514 at
RF transmitter 514 and demodulated into digital data.
Transmit/store data 516 may, when available, transmit the digital
data to a computer system, or when no external communication is
available, may store the digital data for later retrieval, for
example, when RF transmitter 522 surfaces from the borehole.
[0039] Referring now to FIG. 6, a block diagram of selected
elements of an embodiment of method 600 for performing material
loss resistance measurements, as described herein, is depicted in
flowchart form. It is noted that certain operations described in
method 600 may be optional or may be rearranged in different
embodiments.
[0040] In method 600, a downhole sensor including an insulating
substrate and a conductive portion may be placed (operation 602) in
a downhole environment. Electrical current from a current source
may be supplied (operation 604) to two current taps on the
conductive portion. Voltage across two voltage taps on the
conductive portion may be monitored (operation 606) to determine a
change in resistivity. Based on the change in resistivity, an
amount of material loss of a downhole component may be determined
(operation 608), wherein the downhole sensor mimics a material loss
process of the downhole component.
[0041] Turning now to FIG. 7, a block diagram depicting selected
elements of an embodiment of computer system 700 is illustrated.
Computer system may be a personal computer (e.g., desktop or
laptop), tablet computer, mobile device (e.g., personal digital
assistant (PDA) or smart phone), server (e.g., blade server or rack
server), a network storage device, or any other suitable device and
may vary in size, shape, performance, functionality, and price. As
shown in FIG. 7, components of computer system 700 may include, but
are not limited to, processor subsystem 720, which may include one
or more processors, and system bus 721 that communicatively couples
various system components to processor subsystem 720 including, for
example, a memory subsystem 730, an I/O subsystem 740, local
storage resource 750, and a network interface 760. System bus 721
may represent a variety of suitable types of bus structures, e.g.,
a memory bus, a peripheral bus, or a local bus using various bus
architectures in selected embodiments.
[0042] In FIG. 7, network interface 760 may be a suitable system,
apparatus, or device operable to serve as an interface between
computer system 700 and network 755. Network interface 760 may
enable computer system 700 to communicate over network 755 using a
suitable transmission protocol and/or standard, including, but not
limited to, transmission protocols and/or standards enumerated
below with respect to the discussion of network 755. In some
embodiments, network interface 760 may be communicatively coupled
via network 755 to a network storage resource (not shown). Network
755 may be implemented as, or may be a part of, a storage area
network (SAN), personal area network (PAN), local area network
(LAN), a metropolitan area network (MAN), a wide area network
(WAN), a wireless local area network (WLAN), a virtual private
network (VPN), an intranet, the Internet or another appropriate
architecture or system that facilitates the communication of
signals, data and/or messages (generally referred to as data).
Network 755 may transmit data using a desired storage and/or
communication protocol. Network 755 and its various components may
be implemented using hardware, software, or any combination
thereof.
[0043] As depicted in FIG. 7, processor subsystem 720 may include a
system, device, or apparatus operable to interpret and/or execute
program instructions and/or process data, and may include a
microprocessor, microcontroller, digital signal processor (DSP),
application specific integrated circuit (ASIC), or another digital
or analog circuitry configured to interpret and/or execute program
instructions and/or process data.
[0044] Also in FIG. 7, memory subsystem 730 may include a system,
device, or apparatus operable to retain and/or retrieve program
instructions and/or data for a period of time (e.g.,
computer-readable media). The computer system may include
computer-readable instructions (not shown), for example stored by
memory subsystem 730, to perform at least certain portions of the
methods and data processing operations disclosed herein. Memory
subsystem 730 may include random access memory (RAM), electrically
erasable programmable read-only memory (EEPROM), read-only memory
(ROM), a PCMCIA card, a solid state drive (SSD), flash memory,
magnetic storage, opto-magnetic storage, and/or a suitable
selection and/or array of volatile or non-volatile memory. Local
storage resource 750 may include computer-readable media (e.g.,
hard disk drive, floppy disk drive, CD-ROM, and/or other type of
rotating storage media, flash memory, EEPROM, and/or another type
of solid state storage media) and may be generally operable to
store instructions and/or data. Likewise, a network storage
resource (not shown), for example, coupled to network 755, may
include computer-readable media (e.g., hard disk drive, floppy disk
drive, CD-ROM, and/or other type of rotating storage media, flash
memory, EEPROM, magnetic storage devices, optical storage devices,
network storage devices, cloud storage devices, or another suitable
information storage device, and/or a combination of these devices
and/or other type of solid state storage media) and may be
generally operable to store instructions and/or data.
[0045] In FIG. 7, I/O subsystem 740 may include a system, device,
or apparatus generally operable to receive and/or transmit data
to/from/within system 700. In computer system 700, I/O subsystem
740 may represent, for example, a variety of communication
interfaces, graphics interfaces, video interfaces, user input
interfaces, and/or peripheral interfaces. Specifically, I/O
subsystem 740 may include or support interfaces and/or
instrumentation for downhole data acquisition and monitoring of
corrosion and erosion, as described in detail herein.
[0046] The above disclosed subject matter is to be considered
illustrative, and not restrictive, and the appended claims are
intended to cover all such modifications, enhancements, and other
embodiments which fall within the true spirit and scope of the
present disclosure. Thus, to the maximum extent allowed by law, the
scope of the present disclosure is to be determined by the broadest
permissible interpretation of the following claims and their
equivalents, and shall not be restricted or limited by the
foregoing detailed description. For example, the devices and
methods described herein may be adapted for use to monitor oil
piplelines, rather than in a downhole environment.
* * * * *